1. Field of the Invention
The invention is in the field of wellbore logging devices. Specifically, the invention is a method of heating the rock formation to improve the quality of data about rock formations in nuclear magnetic resonance techniques for determining relaxation rates, loss tangent measurements, or in sampling of formation fluids as is done with a fluid sampling device. A suitable fluid sampling device is that used by Baker Hughes in conjunction with services provided under the mark RCISM for formation fluid testing. This includes pressure, temperature, resistivity, capacitance and NMR sensors.
2. Description of the Related Art
Almost all the current well-logging instruments are designed to detect the in-situ fluid and/or formation properties without deliberately altering the environmental states, such as temperature, pressure, etc, of the formation and fluids. In principle, keeping the formation and fluids in their native state is a desirable choice in normal situations. However, because a tool is more sensitive to operation under certain conditions, there are situations where the quality of the measurements will improve if one changes the environmental state of the formation and fluids. As long as the modification does not create adverse effects on the subject formation and fluids, and as long as the change of environment is reversible after the means of modification is removed, measurements taken at the modified state are also valid, and experiments can be designed to be taken at the more favorable, altered state of the formation. This invention disclosure is about designing a tool which changes the environment and makes subsequent measurements, resulting in a more effective characterization of formation properties. Moreover, certain practices such as the heat produced by drilling change the environment temporarily. If an instrument response is more sensitive at a higher temperature, it will be desirable to measure the properties before the drilling induced heat is dissipated. It may also be beneficial to make measurements at different temperatures.
Many petroleum reservoirs in Canada, Venezuela, China, and other countries contain highly viscous oils. Most of the heavy-oil reservoirs are relatively shallow subsurface ones, where the formation water is often fresh, i.e., low in salinity. The lack of conductivity contrast between fresh water and hydrocarbon makes it difficult to quantify hydrocarbon saturations using the resistivity-based and induction-based logging techniques.
NMR and dielectric-based techniques are fundamentally different in the identification of fluid types and quantification of saturations; thus, they are complementary to resistivity-based technique. However, heavy oils present challenges in current NMR logging techniques. The state-of-art NMR logging tool can distinguish water (wetting phase) and hydrocarbon (non-wetting phase) only if their corresponding intrinsic and/or apparent relaxation times pose a significant contrast between the two types of reservoir fluids.
NMR responses are different, depending on whether the reservoir fluids are inside porous rocks or outside. For bulk, liquid-phase fluids, NMR response depends on viscosity and temperature:
                                                        T                              1                ⁢                bulk                                      ⁢                                                  ⁢            or            ⁢                                                  ⁢                          T                              2                ⁢                bulk                                              =                                    A              ·              T                                                      T                0                            ·              η                                      ,                            Eq        .                                  ⁢                  (          1          )                    where A is a fluid-type dependent quantity and differs by a factor of about 2-3 between oil and water, T and T0 are the absolute temperatures in Kelvin at reservoir and ambient conditions, respectively, and η is the viscosity in cP. For water at room temperature, η≈1 cP. On the other hand, heavy oil viscosity is typically two (or more) orders of magnitude higher than that of water in a same temperature.
Although the bulk fluid relaxation time contrast appears useful in distinguishing heavy oil from bulk water, it may not be so useful if the fluids are inside porous rocks. In a rock, one must take into account additional relaxation mechanism arising from the interaction between pore surface and fluids in the pore:
                                                                        T                1                                  -                  1                                            =                                                T                                      1                    ⁢                    bulk                                                        -                    1                                                  +                                  ρ                  ⁢                                                                          ⁢                                      S                    V                                                                                                                                          T                2                                  -                  1                                            =                                                T                                      2                    ⁢                    bulk                                                        -                    1                                                  +                                  ρ                  ⁢                                                                          ⁢                                      S                    V                                                                                                          Eq        .                                  ⁢                  (          2          )                    where S/V is the pore-surface-to-pore-volume ratio and ρ is the surface relaxivity which depends strongly on the wetting characteristics between the fluid and surface of pores. Depending on how large the relaxivity value, ρ, is, the apparent relaxation times could be either dominated by the bulk (1st term in eq. (2)) or surface (2nd term in eq. (2)) relaxation rate. For the majority of reservoirs, water is the wetting phase and oil is the non-wetting one. In this case, the apparent relaxation time of water is dominated by the surface relaxation mechanism, resulting in a much faster apparent relaxation decay than its bulk relaxation produces. Because the surface relaxation time term depends on S/V, the apparent relaxation time is even shorter for smaller sized pores and clays. The water in the smaller pores and clays often associates with water that is irreducible, often known as BVI (Bound Volume Irreducible) and CBW (Clay Bound Water). Although the mechanism for shortening the apparent relaxation times are different for heavy oil and CBW and BVI water, the result is that they overlap each other, and it is often difficult to separate heavy oil from these irreducible water by the difference of their relaxation times.
For most viscous oils, the intrinsic T2 is too short for most NM logging tools to detect. The failure to detect these fastest decaying T2 components results in an underestimation of the porosity of the oil-bearing formation. As can be seen from eq. (1), the relaxation times of oils are proportional to temperature. The viscosity, on the other hand, decreases with temperature. Thus, the relaxation time increases with temperature in the rate higher than linear temperature dependence. As most of the heavy oil reservoirs are shallow, the reservoir temperature is low. For example, a significant amount of heavy oil such as the Athabasca tar sands of Canada and the tar deposits of the Orinoco delta in Venezuela occur at shallow depths. For those reservoirs, underestimation of porosity for the viscous oil sands is highly likely.
Raising temperature can increase relaxation time T2, making the otherwise undetected viscous components detectable, thus rectifying the porosity underestimation problem. On the other hand, the relaxation time of the wetting fluid phase, water, is dominated by surface relaxation, which is much less sensitive to temperature change. Therefore, the shift of T2 towards the longer time alleviates the problem of identifying and quantification of heavy oil saturation from faster relaxing BVI and CBW components.